Hydraulically fracturing or stimulation of subterranean formations to increase oil and gas production has become a routine operation in the petroleum industry. In hydraulic fracturing, a fracturing fluid is injected through a wellbore into the formation at a pressure and flow rate sufficient to overcome the overburden stress and to initiate a fracture in the formation. The fracturing fluid may be a water-based liquid, oil-based liquid, liquefied gas such as but not limited to carbon dioxide, dry gases such as but not limited to nitrogen, or combination of liquefied and dry gases, or some combination of any of these or other fluids. It is most common to introduce a proppant into the fracturing fluid, whose function is to prevent the created fractures from closing back down upon itself when the pressure is released. The proppant is suspended in the fracturing fluid and transported into a fracture. Proppants in use include 20-40 mesh size sand, ceramics, and other materials that provide a high-permeability channel within the fracture to allow for greater flow of oil or gas from the formation to the wellbore.
Stimulation techniques may include the introduction of an acid to dissolve formation or drilling damage, or the introduction of solvent fluids to remove paraffins or wax build-up, or other such techniques.
Production of petroleum or natural gas can be enhanced significantly by the use of these techniques.
Hydraulic fracturing with coiled tubing is a common operation. It generally uses a bottomhole assembly comprised of opposing sets of one or more pressure containment devices such as fracture or packer cups fixed to a length of piping typically heavier in wall thickness than the coiled tubing string. The distance between the two sets of opposing fracture cups determine the length of formation interval to be fractured by virtue of the fact that the cups are fixed to the bottomhole assembly. It is not uncommon in this type of operation to be limited in the length of the interval to be fractured by the distance between the frac cups, which in itself can be limited by lubricator length and / or crane height. Thus there is a maximum distance apart that the perforations can be placed in the casing for the tool to straddle them and isolate the perforations of interest from other sets of perforations higher or lower in the wellbore.
In typical operations, it is desirable to leave the well in a live condition, meaning it is left to flow while operations are being conducted and is not killed with water or heavier liquids. In the case of live-well operations, coiled tubing is seen as having a significant advantage over jointed pipe operations as pressure control at surface is continuous while moving the coiled tubing in and out of the well and there are no joints to be made in the string after the tools are in the wellbore.
To effect a live-well operation, tools used for fracturing are lubricated in and out of the wellbore, a process in which the tools are attached to the coiled tubing and housed in a length of pressure-integral piping known as lubricator and attached to the wellbore above the coiled tubing blowout preventers (BOPs), which themselves are attached to a pressure control valve, commonly referred to as a master valve. After connecting the lubricator housing the coiled tubing fracturing tool and coiled tubing to the master valve, the lubricator system is tested to ensure it holds wellbore pressure without leaking. Well pressure is then contained by the coiled tubing stripper or stuffing box, situated between the lubricator and the injector. Once pressure integrity of the system has been established through testing, the master valve can be opened and the fracturing tool and coiled tubing run into the wellbore to the desired depth for fracturing operations, with the entire operation conducted under live conditions.
In conducting these operations, it is not uncommon for the fracture initiated in one zone or zones to breakthrough behind the casing to an upper zone or zones through open perforations in the casing, thereby reducing the effectiveness of the current fracture treatment, and also potentially impairing future fracture treatments on the upper zone or zones. For example, in stimulating a well in rock that has natural fractures in it, if there are multiple zones of interest to be stimulated, applying pressure to one set of perforations (e.g, the lowest in the wellbore) will cause the fracturing fluid to “short circuit” and follow the natural fractures in the rock and come up to the upper set of perforations, rather than going out into the formation. If a fracturing operations were conducted under these conditions, the proppants, such as sand, carried by the fluid follows the natural fractures and will enter at the bottom set of perforations, loop to the upper perforations and then fall down the wellbore along the tool and pile up behind the lowest packer cup. The tool is then stuck in the hole as it cannot be pulled up against the sandpile. The coiled tubing would need to be cut off to get the tool out. This is very expensive and undesirable, as there are tools stuck at the bottom, the well is no longer being stimulated, and the tools need to be retrieved.